Power production with cogeneration of further products

ABSTRACT

The present disclosure relates to cogeneration of power and one or more chemical entities through operation of a power production cycle and treatment of a stream comprising carbon monoxide and hydrogen. A cogeneration process can include carrying out a power production cycle, providing a heated stream comprising carbon monoxide and hydrogen, cooling the heated stream comprising carbon monoxide and hydrogen against at least one stream in the power production cycle so as to provide heating to the power production cycle, and carrying out at least one purification step so as to provide a purified stream comprising predominately hydrogen. A system for cogeneration of power and one or more chemical products can include a power production unit, a syngas production unit, one or more heat exchange elements configured for exchanging heat from a syngas stream from the syngas production unit to a stream from the power production unit, and at least one purifier element configured to separate the syngas stream into a first stream comprising predominately hydrogen and a second stream.

FIELD OF THE DISCLOSURE

The present disclosure relates to systems and methods for powerproduction with cogeneration of one or more further products. Moreparticularly, one or more chemical products, such as hydrogen, and/orheat production may be provided simultaneously with power production,such as utilizing a supercritical carbon dioxide power cycle.

BACKGROUND

Various methods have been proposed for the production of hydrogen gassuch as through conversion of natural gas (e.g., utilizing steam methanereforming, autothermal reforming, dry reforming, or the like) orconversion of coal and biomass resources (e.g., utilizing gasification,pyrolysis, or the like). For example, U.S. Pat. No. 8,409,307 disclosesa process and system for providing hydrogen at a high level ofreliability from a gasification system by integrating it with steammethane reforming (SMR). The integrated schemes are disclosed therein asmaximizing the reliability of production of high value products such ashydrogen through gasification while minimizing the impact of highnatural gas price on hydrogen production by SMR. There is extensiveactivity throughout the world with respect to producing hydrogen eithervia SMR (which is predominantly used) or through coal gasification (to alesser extent). These are typically standalone chemical productionfacilities. Although less common, it is known to operate plants forsyngas production for both hydrogen generation as well as powerproduction.

Whether hydrogen is generated through the reforming of natural gas orthe gasification of coal, the raw syngas that is produced must undergofurther processing before a nominally pure stream of hydrogen iscreated. Often fossil fuel derived syngas will undergo conversion andremoval of nitrogen, sulfur, and carbon based compounds throughdedicated pieces of equipment/plants. Additionally, ancillary processesare often required in order to support the nitrogen, sulfur, and carbonhandling facilities. This can include any number of processing stepsincluding: high temperature steam heat recovery; low temperature heatrejection; process stream refrigeration; particulate filtration; heavymetals removal; water-gas shift reactions; carbonyl sulfide hydrolysis;hydrodesulfurization reactions; hydrodenitrogenation reactions;methanation reactions; acid gas stripping of hydrogen sulfide; acid gasstripping of carbon dioxide; and condensate removal. The application ofthese processing steps leads to large CAPEX and OPEX requirements inaddition to the loss of energy due to variations in equipmenttemperature requirements and associated heat transfer inefficiencies.Furthermore, hydrogen production facilities that are paired with powergeneration units typically provide fuel to the power cycle in the formof excess syngas, separated hydrogen (should CCS be required), or wastetail gases (e.g., polluted hydrogen streams). Such approaches lead tovaluable feedstock derived hydrogen being consumed. Accordingly, thereremains a need in the art for processes allowing for efficientcogeneration of power as well as various further products, such ashydrogen.

SUMMARY OF THE DISCLOSURE

The present disclosure relates to cogeneration of power and one or morefurther products, such as a chemical product or an energy product (e.g.,heat). In one or more embodiments, the present disclosure particularlycan be configured to utilize a high pressure stream to facilitate heatrecuperation and power generation while providing a cooled processstream that can be further treated to provide one or more chemicalproducts. For example, raw syngas can undergo simple ambient temperatureremoval of one or more of solids, metals, and condensates prior toundergoing a gas separation to provide a stream of hydrogen gas. Furtherprocess streams can then be combined as needed to generate a variety ofeven further chemical products.

In one or more embodiments, the present disclosure thus can providemethods for co-generation of power and one or more chemical products. Inexample embodiments, such methods can comprise: carrying out a powerproduction cycle effective for generating power; providing a heatedstream comprising at least carbon monoxide and hydrogen; cooling theheated stream comprising at least carbon monoxide and hydrogen such thatheat therefrom is transferred to at least one stream in the powerproduction cycle and a cooled stream comprising at least carbon monoxideand hydrogen is provided; and subjecting the cooled stream comprising atleast carbon monoxide and hydrogen to one or more purification steps soas to provide a stream comprising predominately hydrogen. In furtherembodiments, such methods can be characterized in relation to one ormore of the following statements, which can be combined in any numberand order.

Carrying out the power production cycle can comprise carrying out acombustion step where fuel is combusted in the presence of a workingfluid comprising CO₂.

The heated stream comprising at least carbon monoxide and hydrogen canbe a syngas stream.

The syngas stream can be formed in a syngas generation unit.

The heat created in the power production cycle can be transferred to thesyngas generation unit.

The heat from the heated stream comprising at least carbon monoxide andhydrogen can be transferred to a stream of recycled CO₂ in the powerproduction cycle.

The method further can comprise passing a portion of the cooled streamcomprising at least carbon monoxide and hydrogen to the power productioncycle for combustion therein.

Subjecting the cooled stream comprising at least carbon monoxide andhydrogen to one or more purification steps can be effective to provide asecond stream that is a hydrogen-depleted stream.

The method further can comprise passing at least a portion of thehydrogen-depleted stream to the power production cycle for combustiontherein.

The method further can comprise passing at least a portion of thehydrogen-depleted stream through a separation unit configured toseparate carbon dioxide therefrom.

The separation unit can be a low temperature CO₂ separation unitconfigured to cool the at least a portion of the hydrogen-depletedstream to a temperature sufficient for separation of the carbon dioxidein a liquefied form.

The low temperature CO₂ separation unit can be configured to cool the atleast a portion of the hydrogen-depleted stream to a temperature that isabout 2° C. to about 25° C. greater than a freezing temperature of theat least a portion of the hydrogen-depleted stream.

The method further can comprise combining at least a portion of thestream comprising predominately hydrogen with nitrogen from a nitrogensource under conditions effective to form ammonia.

The nitrogen source can be an air separation unit.

The oxygen from the air separation can be utilized as an oxidant in oneor both of the power production cycle and a syngas generation unit.

The method further can comprise combining carbon dioxide with at least aportion of the ammonia under conditions effective to form urea.

At least a portion of the carbon dioxide can be withdrawn from the powerproduction cycle.

In one or more embodiments, the present disclosure can provide systemsfor co-generation of power and one or more chemical products. In exampleembodiments, such systems can comprise: a power cycle unit configuredfor power generation; a syngas generation unit effective for providing aheated syngas stream; one or more heat exchange elements configured forexchanging heat from the heated syngas stream to at least one stream inthe power cycle unit and providing a cooled syngas stream; and at leastone separation unit configured to separate the cooled syngas stream intoa first stream comprising predominately hydrogen and a second stream. Infurther embodiments, such systems can be further characterized inrelation to one or more of the following statements, which can becombined in any number or order.

The system further can comprise an ammonia synthesis unit configured toreceive at least a portion of the first stream comprising predominatelyhydrogen and to receive a stream comprising nitrogen and form a streamcomprising ammonia.

The system further can comprise an air separation unit configured forproviding oxygen to the power cycle and for providing the streamcomprising nitrogen to the ammonia synthesis unit.

The system further can comprise a urea synthesis unit configured toreceive at least a portion of the stream comprising ammonia and toreceive a stream comprising carbon dioxide and form a stream comprisingurea.

The system further can comprise a CO₂ separation unit configured toreceive at least a portion of the second stream and provide the streamcomprising carbon dioxide.

The at least one separation unit can include one or both of a membraneseparator and a pressure swing adsorption unit.

These and other features, aspects, and advantages of the disclosure willbe apparent from a reading of the following detailed descriptiontogether with the accompanying drawings, which are briefly describedbelow. The invention includes any combination of two, three, four, ormore of the above-noted embodiments as well as combinations of any two,three, four, or more features or elements set forth in this disclosure,regardless of whether such features or elements are expressly combinedin a specific embodiment description herein. This disclosure is intendedto be read holistically such that any separable features or elements ofthe disclosed invention, in any of its various aspects and embodiments,should be viewed as intended to be combinable unless the context clearlydictates otherwise.

BRIEF SUMMARY OF THE FIGURES

FIG. 1 is a flow diagram showing a power production cycle and elementsthereof useful in a co-generation system and process according toembodiments of the present disclosure.

FIG. 2 is a flow diagram showing a combination of elements usefulaccording to embodiments of the present disclosure for forming aplurality of end products, including, but not limited to, power andhydrogen.

FIG. 3 is a flow diagram showing a combination of elements usefulaccording to embodiments of the present disclosure for forming aplurality of end products, including, but not limited to, power,ammonia, and carbon dioxide.

FIG. 4 is a flow diagram showing a combination of elements usefulaccording to embodiments of the present disclosure for forming aplurality of end products, including, but not limited to, power and oneor more chemical products.

DETAILED DESCRIPTION OF THE DISCLOSURE

The present subject matter will now be described more fully hereinafterwith reference to exemplary embodiments thereof. These exemplaryembodiments are described so that this disclosure will be thorough andcomplete, and will fully convey the scope of the subject matter to thoseskilled in the art. Indeed, the subject matter can be embodied in manydifferent forms and should not be construed as limited to theembodiments set forth herein; rather, these embodiments are provided sothat this disclosure will satisfy applicable legal requirements. As usedin the specification, and in the appended claims, the singular forms“a”, “an”, “the”, include plural referents unless the context clearlydictates otherwise.

In one or more embodiments, the present disclosure provides forcogeneration of power and one or more further products (e.g., a chemicalentity or entities and/or heat) through operation of a power productioncycle and treatment of a high pressure stream, such as a syngas stream.The present systems and methods thus can utilize heat transfer betweentwo or more processes or processing units to improve efficiency of oneor more of the processes. Likewise, the present systems and methods canbeneficially provide one or more product streams at a reduced costcompared to known methods for preparing such products.

As used herein syngas (or synthesis gas) is understood to reference achemical mixture comprising at least hydrogen and carbon monoxide. Thesyngas is typically a gaseous mixture, although a mixed-phase syngas mayalso be utilized. Moreover, although it can be preferable to utilize asubstantially pure syngas stream (e.g., comprising 95% or greater, 99%or greater, or 99.5% or greater hydrogen and carbon monoxide), thepresent disclosure does not necessarily exclude the presence of furtherchemical moieties in the syngas being utilized. The syngas can besubjected to one or more treatment steps as otherwise described hereinto generate one or more desired chemical products, and the treatmentsteps can include utilization of one or more streams generated in aco-operated power production cycle.

A power production cycle as discussed herein, or a power productionplant, can incorporate a variety of elements for carrying out the powerproduction cycle. Non-limiting examples of elements that may be includedin a power production plant (and method of operation thereof) accordingto the present disclosure are described in U.S. Pat. Nos. 8,596,075,8,776,532, 8,869,889, 8,959,887, 8,986,002, 9,062,608, 9,068,743,9,410,481, 9,416,728, 9,546,814, 10,018,115, and U. S. Pat. Pub. No.2012/0067054, the disclosures of which are incorporated herein byreference.

In one or more embodiments, a power production cycle useful according tothe present disclosure can include any system and method wherein CO₂(particularly supercritical CO₂— or sCO₂) is used in a work stream. As anon-limiting example, a recycle CO₂ stream is provided at hightemperature and high pressure, is input to a combustor wherein acarbonaceous fuel is combusted in oxygen, is expanded across a turbineto produce power, is cooled in a heat exchanger, is purified to removewater and any other impurities, is pressurized, is re-heated using theheat taken from the turbine exhaust, and is again passed to thecombustor to repeat the cycle. Such system and method are beneficial inthat all fuel and combustion derived impurities, excess CO₂, and waterare removed as a liquid or a solid (e.g., ash), and there is virtuallyzero atmospheric emission of any streams. The system and method achieveshigh efficiency through, for example, the use of low temperature level(i.e., less than 500° C.) heat input after the recycle CO₂ stream hasbeen re-pressurized and before combustion.

A power production cycle according to the present disclosure can includemore steps or fewer steps than described above and can generally includeany cycle wherein a high pressure recycle CO₂ stream is expanded forpower production and recycled again for further power production. Asused herein, a high pressure recycle CO₂ stream can have a pressure ofat least 100 bar (10 MPa), at least 200 bar (20 MPa), or at least 300bar (30 MPa). A high pressure recycle CO₂ stream can, in someembodiments, have a pressure of about 100 bar (10 MPa) to about 500 bar(50 MPa), about 150 bar to about 450 bar (45 MPa), or about 200 bar (20MPa) to about 400 bar (40 MPa). Reference to a high pressure recycle CO₂stream herein may thus be a CO₂ stream at a pressure within theforegoing ranges. Such pressures also apply to references to other highpressure streams described herein, such as a high pressure work streamcomprising CO₂. In some embodiments, a power production cycle can be acycle wherein a recycled CO₂ stream is subjected to repeatedcompression, heating, combustion, expansion for power production, andcooling.

As a non-limiting example, a power production system 100 and method ofuse thereof is illustrated in FIG. 1. As illustrated therein, a powerproduction cycle can include a combustor 115 where a carbonaceous fuelfeed 112 and an oxidant feed 114 are combusted in the presence of arecycle CO₂ stream 138 to form a high pressure, high temperaturecombustion product stream 117 that is expanded in a turbine 120 toproduce power with a generator 145. The exhaust stream 122 from theturbine 120 at high temperature is cooled in a recuperative heatexchanger 125 to produce a low pressure, low temperature CO₂ stream 127that is passed through a separator 130 with condensed products 132(e.g., water) and a substantially pure recycle CO₂ stream 133 exitingtherefrom. A substantially pure recycle CO₂ stream can comprise at 95%,at least 98%, at least 99%, or at least 99.5% molar CO₂. Thesubstantially pure recycle CO₂ stream 133 is compressed in compressor135 to form the high pressure recycle CO₂ stream 138 (e.g., having apressure in a range as described above) that is passed to therecuperative heat exchanger 125 where it is heated against the coolingturbine exhaust stream 122.

A power production cycle such as shown in FIG. 1 can be advantageous foruse according to the present disclosure at least in part because of theability to recuperate a significant amount of the heat from the turbineexhaust 122 for use in re-heating the recycle CO₂ stream aftercompression and before passage to the combustor 115. Efficiency,however, can be limited by the ability to add enough heat to raise thetemperature of the recycle CO₂ stream 138 exiting the hot end of therecuperative heat exchanger 125 to be sufficiently close to thetemperature of the turbine exhaust 122 entering the hot end of therecuperative heat exchanger. The need for input of additional heating isidentified in U.S. Pat. No. 8,596,075, and various possible sources oflow grade heat (e.g., at a temperature of less than about 500° C.) areidentified.

In some embodiments, a power production cycle for use as describedherein can include any power production cycle whereby a working fluidcomprising CO₂ is repeatedly cycled at least through stages ofcompressing, heating, expansion, and cooling. In various embodiments, apower production cycle for use according to the present disclosure mayinclude combinations of the following steps:

-   -   combustion of a carbonaceous fuel with an oxidant in the        presence of a recycled CO₂ stream to provide a combustion        product stream at a temperature of at least about 500° C. or at        least about 700° C. (e.g., about 500° C. to about 2000° C. or        about 600° C. to about 1500° C.) and a pressure of at least        about 100 bar (10 MPa) or at least about 200 bar (20 MPa) (e.g.,        about 100 bar (10 MPa) to about 500 bar (50 MPa) or about 150        bar (15 MPa) to about 400 bar (40 MPa));    -   expansion of a high pressure recycled CO₂ stream (e.g., at a        pressure as noted above) across a turbine for power production;    -   cooling of a high temperature recycled CO₂ stream (e.g., at a        pressure as noted above), particularly of a turbine discharge        stream, in a recuperative heat exchanger;    -   condensing of one or more combustion products (e.g., water) in a        condenser, the combustion products being present particularly in        a combustion product stream that has been expanded and cooled;    -   separating water and/or further materials from CO₂ to form a        recycled CO₂ stream;    -   compressing a recycled CO₂ stream to a high pressure (e.g., a        pressure as noted above), optionally being carried out in        multiple stages with optional inter-cooling to increase stream        density; and    -   heating a compressed recycled CO₂ stream in a recuperative heat        exchanger, particularly heating against a cooling turbine        exhaust stream.

In further embodiments, the present disclosure also relates to powerproduction systems. In particular, such systems can comprise one or morepumps or compressors configured to compress a CO₂ stream to a highpressure as described herein. The systems can comprise one or morevalves or splitters configured to divide the compressed CO₂ stream intoat least a first portion CO₂ stream and a second portion CO₂ stream. Thesystems can comprise a first heat exchanger (or heat exchange unitcomprising a plurality of sections) configured to heat a CO₂ streamagainst a high temperature turbine discharge stream and optionallyprovide heating to one or more further streams. The systems can compriseat least one turbine configured to expand a CO₂ containing stream toproduce power. The systems can comprise one or more transfer elementsconfigured to transfer heat between one or more streams. The systems cancomprise a combustor configured to combust a carbonaceous fuel in anoxidant in the presence of the CO₂ stream.

The systems of the present disclosure can comprise at least onecompressor configured to compress a CO₂ stream to a high pressure asdescribed herein, at least one combustor downstream from the compressor,at least one turbine downstream from the combustor and upstream from thecompressor, and at least one heat exchanger positioned to receive astream from the at least one compressor and to receive a separate streamfrom the at least one turbine. Optionally, a separator can be positioneddownstream from the heat exchanger and upstream from the compressor.Further optionally, a compressor can be positioned upstream from thecompressor and downstream from the first heat exchanger. The system canfurther comprise one or more valves or splitters as necessary.

As previously discussed, a power production cycle, being configuredaccording to any useful embodiments including, but not limited, to thosedescribed above, can be combined with forming and/or processing of asyngas stream in a manner such that further, useful products areprovided in addition to the power attributable to the power productioncycle. Systems and methods suitable for such cogeneration of power andone or more further products is illustrated according to one or moreembodiments of the present disclosure in FIG. 2.

A power cycle 201 is illustrated in FIG. 2 and can be any power cycleconfigured for production of power and being capable of receiving andproviding one or more heated streams and, optionally, carbon dioxide.Thus, the power cycle 201, may be a supercritical CO₂ power cycleutilizing components and operations as already described above, and thepower cycle may include one or more of the components described inrelation to FIG. 1. The power cycle 201 receives fuel in line 202 from afuel source 204, receives oxidant through line 211 from an oxidantsource 210, provides power 205 (e.g., electricity) as an output, andoptionally can provide a CO₂ stream through line 207 as a furtheroutput. The oxidant source 210 may be, for example, an air separationunit (ASU) configured for providing substantially pure oxygen (e.g., atleast 95%, at least 98%, at least 99%, or at least 99.5% molar O₂);however, other oxygen sources or oxidant sources may be utilized. Theoxidant source 210 may likewise be a nitrogen source. For example, andASU can be effective to separate air into a stream of predominatelyoxygen and a stream of predominately nitrogen. Thus, in someembodiments, the same unit can be configured to be one or both of anoxidant source and a nitrogen source.

Pressurized raw syngas can be processed to generate one or more endproducts, and the syngas can be provided from a variety of sources, suchas being generated by gasification or reforming of a suitable feedstock.The pressurized, raw syngas can be provided into the process illustratedin FIG. 2 as a preformed, sourced material. Alternatively, asillustrated, the syngas optionally can be formed directly as part of theoverall process. As shown, fuel in line 221, steam in line 223, andoxidant in line 213 are introduced to a syngas generation unit 220 toprovide the pressurized, raw syngas stream in line 225. As illustrated,the syngas generation unit 220 may be a single component or can includea plurality of components that are configured to provide thepressurized, raw syngas stream. In some embodiments, the syngasgeneration unit 220 can be configured to receive heating from the powercycle 201. As illustrated by line(s) 224, one or more streams may bepassed between the power cycle 201 and the syngas generation unit 220 sothat heat from the power cycle may be added to the syngas generationunit. For example, heating from a turbine exhaust stream from the powercycle 201 may be transferred directly (e.g., turbine being passed to aheat exchanger in the syngas generation unit 220) or indirectly (e.g., aheat transfer fluid can be used to transfer heat) through line(s) 224.Line 224 is illustrated as dashed to show that it is optional, and thearrow illustrates the direction in which heat is transferred.

The pressurized, raw syngas in line 225 can be processed incooling/conditioning unit 230, and such processing can include onlycooling, can include only one or more conditioning steps, or can includeboth of cooling and conditioning. For example, the raw syngas can becooled against a high pressure stream of a heat transfer medium (such ascarbon dioxide or even a fuel stream) taken from the power cycle 201,and this heat transfer medium can be utilized for heat recuperation andadditional power generation. As illustrated in FIG. 2, line 234 is showndashed to illustrate that it is optional, and the arrow illustrates thedirection in which heat is transferred. In other embodiments, coolingcan be carried out by additional or alternative processes. For example,the steam in line 223 may be at least partially generated by heating awater stream using heat from the cooling/conditioning unit 230.

In some embodiments, conditioning of the syngas can be carried outsequentially with cooling. For example, the cooled syngas can then bepurified, such as by applying one or more of dewatering, filtering forfine particulate matter, removal of soluble acid gas, and heavy metalremoval. As such, it is understood that the cooling/conditioning unitmay comprise a plurality of individual components, such as one or morefilter units, one or more liquid separation units, one or more membraneunits, and the like, and such optional units are illustrated as 230 a,230 b, and 230 c. The cooling/conditioning unit 230 thus may provide,through line 236, one or more of hydrogen sulfide (H₂S), CO₂, water,tar, particulates, heavy metals, and/or similar materials that can beseparated from the raw syngas. Optionally, clean syngas may be used asall or part of the fuel for the power cycle 201 in line 202. The cleansyngas is shown in line 237 being combined with line 202, but it isunderstood that line 237 may pass directly to a component of the powercycle 201, such as a combustor.

The at least partially purified syngas stream in line 239 (andoptionally in line 237), preferably will be nominally dry and cooled. Inone or more embodiments, all or part of the purified syngas istransferred through line 239 to a hydrogen separation unit 240, whichitself can include one or more separation components. The hydrogenseparation unit 240, for example, may include a gas membrane, a pressureswing absorber (PSA), and/or another gas separation system that can beadapted to or configured to favor the separation of hydrogen via itssmall kinetic diameter and partial pressure. For example, so-calledprism membranes (available from Air Products) can be particularlysuitable for such separation. In general, the relative permeation rateof gas molecules through such membranes (in descending order) is H₂O,H₂, NH₃, CO₂, H₂S, O₂, Ar, CO, N₂, CH₄, C₂H₄, and C₃H₈. The membraneand/or further separation component can enable the formation of twoseparate flows from the hydrogen separation unit. A first stream in line243 can be predominantly hydrogen (e.g., greater than 50%, greater than60%, greater than 75%, greater than 85%, or greater than 90% molarhydrogen). A second stream in line 245 can comprise any one or more ofhydrogen, N₂, Ar, CO, CO₂, H₂S, COS, CH₄, C₂H₄, C₃H₈, and any furthercompounds that may have been part of the original syngas input.Preferably, the second stream will be hydrogen lean (e.g., less than50%, less than 25%, or less than 10% molar) and, as such, the secondstream can be referenced as being a hydrogen-depleted stream. Such ahydrogen-depleted stream typically can comprise some combination of H₂(preferably in a low concentration), CO₂, CO, CH₄, N₂, and Ar. In thismanner, the present systems and methods can provide one or morecarbonaceous compounds that may be separated from a hydrogen containingstream without the need for dedicated removal equipment targeting thenon-hydrogen species' groups. Similarly, the present disclosure can beuseful to provide handling of carbonaceous compounds includingexport/disposal, wherein such handling is provided by the power cyclecombustion and compression regimes. Likewise, the present systems andmethods can be useful to reduce/eliminate water consumption for theproduction of hydrogen in that hydrogen production via WGS is notrequired (although it may be optionally utilized if desired).Specifically, this can be the case since residual feedstock is used aspower cycle fuel. The power cycle serves as a means of balancing lostrevenue that would have been generated by additional hydrogen as well asa CAPEX offset.

In one or more embodiments, the H₂ product provided through line 243 canbe separated using H₂ pressure swing absorption (PSA) technology. Insuch embodiments, the processing, cleanup, and cooling of the syngas maybe carried out in the cooling/conditioning unit 230 such that syngaswith a required H₂ content and a desired impurity level can be presentin line 239 for input at the inlet of a PSA unit. This can include, forexample, carrying out one or more of the following processing steps inthe cooling/conditioning unit 230 or in one or more further unitscombined therewith: carrying out sour or sweet water gas shift;providing for particulate and/or heavy metal removal; carrying ourcarbonyl sulfide (COS) hydrolysis; carrying out removal of sulfurousmaterial, such as H₂S, in an acid gas removal step; and partial or deepremoval of CO₂. It can be preferred to carry out such separation stepssuch that the stream in line 239 entering the hydrogen separation unit240 has a hydrogen content of at least 60% by volume. It is possible toachieve a high hydrogen recovery efficiency using PSA separation whenthe feed stream entering the unit 240 has a relatively high hydrogencontent with low contaminate levels, the presence of which may bedetrimental to the lifetime of adsorbent material used in the PSA. It isgenerally desirable to achieve an H₂ recovery efficiency of greater than75%, greater than 80%, or greater than 85% in the H₂ PSA unit, whichsuch unit it utilized.

The first stream in line 243 exiting the hydrogen separation unit(comprising predominately hydrogen gas) can be sent on for finalprocessing, if needed, and then can be used as a chemical feedstock inadjacent facilities and/or exported. The second stream in line 245(i.e., the hydrogen-depleted stream) exiting the hydrogen separationunit 240 can be input as at least a portion of the fuel in line 202 inthe co-operated power cycle 201. Line 245 thus may combine with line 202or be input directly to a component of the power cycle 201. The secondgas stream can be compressed to a sufficiently high pressure(potentially being pre-heated against the raw syngas as notedpreviously) and combusted with nominally pure oxygen in the powercycle's combustor/turbine. Line 245 thus may be input to a compressor(see element 135) of the power cycle 201 and/or a like compressor may bepositioned directly in line 245. The resulting turbine exhaust gas inthe power cycle 201 thus can be a mixture of predominantly carbondioxide and water with traces of (but not exclusively) O₂, N₂, Ar, NO,and SO₂. Referring to FIG. 1 as an example embodiment of the power cycle201), the turbine exhaust gas can be cooled (e.g., in a recuperativeheat exchanger train), such as down to a temperature approaching ambienttemperature. Upon the exit of the heat recovery train, the exhaust gasin line 122 can be provided to a water separator 130 for one or morepurification steps. The purification can include removal of NOx and SOximpurities to provide a nominally dry and substantially pure stream ofcarbon dioxide in line 133. A suitable purification unit can be, forexample, a DeSNOx unit 470 as described in relation to FIG. 4 below. Thesubstantially pure carbon dioxide can be pressurized (e.g., as part ofthe power cycle's working fluid recovery process). If desired, sulfurspecies can also be removed from the syngas via conventional acid gasremoval processes prior to syngas combustion. A portion of thepressurized carbon dioxide can be drawn from the working fluid (e.g., inline 207) in order to maintain a mass balance with the fuel and oxygenentering the power production cycle. The withdrawn carbon dioxide streammay be vented, sequestered, or sent on for use as a feedstock in adownstream chemical process, such as urea production.

In some embodiments, the second stream exiting the hydrogen separationunit 240 in line 245 may be further processed in a CO₂ separation unit250 to recover and purify at least a portion of its CO₂ content. The CO₂separation unit 250 is preferably a low temperature unit. A lowtemperature CO₂ separation unit can be a unit that is configured to coolat least a portion of the second stream exiting the hydrogen separationunit (i.e., a hydrogen-depleted stream) to a temperature sufficient forseparation of any carbon dioxide therein so as to be in a liquefiedform. For example, a suitable low temperature CO₂ separation unit can beone that is configured to cool at least a portion of the second streamto a temperature that is above but within about 50° C., within about 40°C. or within about 30° C. of the freezing temperature of the secondstream. More particularly, the low temperature CO₂ separation unit canbe configured to cool to a temperature that is about 2° C. to about 25°C., about 2° C. to about 15° C., or about 1° C. to about 5° C. greaterthan the freezing temperature of the second stream. In such embodiments,it can be desirable to design the overall process such that the CO₂content of the stream in line 245 can be at least 40% by volume of thetotal output from the hydrogen separation unit 240. This can bebeneficial to reduce the overall cost of CO₂ separation in a lowtemperature system. In some embodiments, a preferred CO₂ separationprocess can implement CO₂ separation as a liquid at a low temperaturewithin about 1° C. to about 5° C. of the freezing temperature of thecompressed dried gas mixture in line 245. The residual CO₂ partialpressure in the separated uncondensed gas stream will be at a pressurein the range of about 6 bar to about 7 bar. The low pressure gas streamin line 245 can be compressed to a pressure of about 20 bar to about 70bar in compressor 247. Higher pressures favor higher CO₂ recovery in theseparated liquid CO₂ phase. The compressed gas then can be dried in adesiccant drier 249, which can be thermally regenerated. For example,when an ASU is used as the oxidant source 210, N₂ taken from the ASU inline 219 can be used for heating in the desiccant drier 249. The dried,compressed gas then enters the CO₂ separation unit 250. Carbon dioxidecan exit the separation unit 250 in line 251 and preferably can have apurity level of at least 80%, at least 90%, at least 95%, or at least99% molar CO₂. Residual H₂, along with the CO and CH₄ separated from H₂in the hydrogen separation unit 240 can exit the CO₂ separation unit 250through line 253. This uncondensed gas, which is at elevated pressure,can be used as the supplementary fuel in the power cycle 201.

The syngas conditioning and cleanup in the cooling/conditioning unit 230can, in some embodiments, involve partial removal of CO₂ in an acid gasremoval step to obtain syngas that has a desired H₂ content prior to theH₂ recovery step. In such embodiment, CO₂ removal can be adjusted suchthat the cleaned syngas product in line 239 has an H₂ content of atleast 60% and preferably at least 70% by volume. In such embodiments,the waste gas in line 245 exiting the H₂ separation unit 240 may beconcentrated in CO₂ which would make it a preferred quality for lowtemperature CO₂ separation.

In one or more embodiments, a carbon dioxide product stream (e.g., oneor both of stream 207 and stream 251) may be used as a feedstock forchemical production, such as urea synthesis, methanol synthesis,dimethyl ether (DME) synthesis, carbon-cured cement, and synthesis offurther products. Beneficially, hydrogen required to generate furtherchemicals may be sourced from the first gas stream in line 243 exitingthe hydrogen separation unit 240 (i.e., the stream of predominatelyhydrogen gas). For example, hydrogen from line 243 and nitrogen fromline 219 (or otherwise sources) may be input to an ammonia synthesisunit 260 to create ammonia (in line 261). Similarly, ammonia formed inthis manner (or otherwise source ammonia) can be combined withsubstantially pure carbon dioxide (e.g., from stream 207 and/or stream251) to create urea. The nitrogen stream in line 219 can be taken fromthe ASU and pressurized according to the requirement of the ammoniaprocess, typically to a pressure of about 100 bar or greater. This maybe a pressure as taken from the ASU or, in some embodiments, a separatecompressor may be provided in-line with line 219 (see compressor 219 a).Ammonia production reactions are highly exothermic and consequently asignificant amount of heat (e.g., in the range of about 400° C. to about600° C.) is typically generated in ammonia production processes. Thisheat can be recovered using a heat transfer fluid such as supercriticalcarbon dioxide and/or water and utilized as supplemental heating in thepower production cycle to enhance the efficiency of power generation.This is shown by line 262, which can be input to the power cycle 201.

The presently disclosed systems and methods can allow for substantialelimination or complete elimination of dedicated nitrogen, sulfur,and/or carbon handling systems during the processing of raw syngas forhydrogen production. Furthermore, the presently disclosed systems andmethods can provide a desirable level of thermodynamic efficiency thatcan be comparable to or greater than that of current processes whilesimultaneously reducing system complexity. This can be achieved, atleast in part, due to the ability to use low quality sensible heat inthe co-operated power cycle 201 (e.g., power cycle 100 in FIG. 1). Forexample, U.S. Pat. No. 8,596,075, the disclosure of which isincorporated herein by reference, describes methods for low grade heatintegration to improve efficiency of a power production cycle, and suchlow grade heat integration can likewise be incorporated into the powerproduction cycle utilized according to the present disclosure. This cansubstantially or completely eliminate the need for additional hydrogenproduction through water gas shift (WGS) reactions in order to maintainproduction/feedstock utilization efficiency. Through the elimination ofsuch further equipment requirements (e.g., for carrying out WGSreactions, methanation units, and the like), the parasitic energyconsumption associated with hydrogen production can be reduced over thatof traditional processes. In addition, the integration of hydrogenproduction with the power production cycle can also enables carbondioxide capture and compression without the addition of equipment beyondthe existing requirements of the power cycle. Moreover, unlikepolygeneration concepts where power must be produced using hydrogen orclean syngas, the fuel provided to the power production cycle accordingto the present disclosure can be include a significant concentration ofcarbon monoxide while also being hydrogen-depleted, thereby allowing forthe greatest preservation of the feedstock's hydrogen content withminimal upstream processing.

The presently disclosed systems and methods can be particularlybeneficial in that carbon capture units that are required in knownsystems (and are typically significantly expensive) can be completelyeliminated. Likewise, full conversion of water-gas-shift reactors is notrequired according to the present disclosure. Even further, highpressure steam generation equipment can be eliminated since low-grade,sensible heat can be used for improved energy efficiency, as notedabove, and complicated cooling/refrigeration trains needed formethanation and carbon dioxide capture solvents can also be eliminated.In comparison to known systems, the present disclosure can providesystems and methods that are cost effective, highly efficient, andeffective for substantial or complete carbon capture with co-powergeneration. Thus, the present disclosure provides an easilyimplementable poly-generation system and method that has not heretoforebeen achievable according to the prior art.

In light of the foregoing, the present disclosure can provide a varietyof configurations wherein cogeneration of power and at least hydrogencan be provided. In such embodiments, a hot syngas stream 225 can beprovided from the syngas generation unit 220, which can operate via, forexample, coal gasification and/or natural gas partial oxidation, and/ornatural gas reforming. The hot syngas stream 225 can be at leastpartially cooled in unit 230, such as by using a heat transfer fluid. Inpreferred embodiments, the heat transfer fluid can be a carbon dioxidestream and/or a water stream that is utilized in the power cycle 201.The heat transfer fluid particularly can comprise at least supercriticalcarbon dioxide. Utilization of the carbon dioxide stream (or otherstream) from the power production cycle to cool the syngas stream can beparticularly useful to enhance the efficiency of the power generationprocess. For example, heat transferred from the syngas stream 225 to thecarbon dioxide stream (e.g., the stream in line 234) can be used for lowgrade heating of the recycle carbon dioxide stream in the power cycle toimprove the cycle efficiency as previously discussed. The final cooledgas temperature is determined according to the inlet temperature of aWater-Gas Shift (WGS) step that can be carried out in the syngasgeneration unit 220. The WGS step can be beneficial to react carbonmonoxide with steam and generate added hydrogen and carbon dioxide tothe system. Shifting can be performed on a slipstream of syngas and notthe total syngas stream in order to reduce the cost of shift process andassociated equipment. In such as case, the shift step can be designedsuch that the hydrogen concentration in the recombined total syngasstream can be enough for economic downstream separation. This can beachieved by controlling one or more of the steam fed into the shiftreactor, the size of the catalyst bed, and flow rate of the slipstreamto the shift reactors. Pressure swing absorber hydrogen recovery bedstypically requires at least 60% molar hydrogen in the feed stream toachieve economic hydrogen recovery (e.g., at least 80% molar hydrogenrecovery). When hydrogen sulfide is present in the high temperaturesyngas stream (e.g., when the syngas is provided from a partialoxidation step), a sour WGS step followed by a downstream acid gasremoval for hydrogen sulfide separation is typically utilized. In sourWGS, sulfur resistant shift catalysts, such as cobalt-molybdenum basedcompositions, can be used. Shifted syngas potentially cleaned fromsulfur contaminants can then be fed into a hydrogen separation andrecovery unit.

When cogeneration of power and hydrogen is desired, as discussed above,the tail gas (see line 245 in FIG. 2 or line 253 in FIG. 3) from thehydrogen separation unit 240 can be used as a fuel gas for powergeneration in a supercritical carbon dioxide power cycle such asdescribed herein. The tail gas from a PSA hydrogen recovery unittypically can be at a pressure of about 1 to 2 bar and can containhydrogen, carbon oxides, and methane. The tail gas can be pressurized(see compressor 247, which optionally may be present in line 245 in FIG.2 as well) and sent to power production plant as fuel gas. Excessiveshifting of the syngas prior to hydrogen recovery can reduce the heatingvalue of the tail gas from the hydrogen separation unit 240, which willconsequently reduce the amount of power that can be generated.

The WGS reaction is exothermic and thus the syngas stream temperaturewill rise along the length of the shift reactor. The heat from shiftedsyngas can be recovered using a heat transfer fluid such assupercritical carbon dioxide or water and utilized in a supercriticalcarbon dioxide power cycle to enhance the efficiency of powergeneration. After heat recovery from shifted syngas and further cooling,a total syngas stream can be optionally directed to an acid gas removalunit to selectively remove hydrogen sulfide.

In further embodiments, in addition to generation of power, hydrogen,and ammonia, the presently disclosed systems and methods can further beuseful in production of urea. As such, a urea synthesis unit can beincluded downstream of the ammonia production train. This is shown inthe embodiment illustrated in FIG. 4; however, it is understood that theurea synthesis unit may likewise be incorporated in the embodimentsillustrated in FIG. 3.

Referring to FIG. 4, fuel in line 421 is passed to the syngas generationunit 420, which may be configured as otherwise described above.Moreover, one or more further feed streams (e.g., a steam stream) may beinput to the syngas generation unit 420 as desired. Raw syngas exits thesyngas generation unit in line 425 and is passed to the hydrogenseparation unit 440. If needed, a cooling and/or conditioning unit (seeunit 230 above) may be provided between the syngas generation unit 420and the hydrogen separation unit 440 to achieve the desired conditionsof the raw syngas entering the hydrogen separation unit. A fuel gasexiting the hydrogen separation unit 440 through line 445 can be passedto a power cycle combustor/turbine while a stream of predominatelyhydrogen exits the hydrogen separation unit 440 in line 443. The fuelgas in line 443 is a hydrogen-depleted stream of one or more fuel gasesand preferably can include a significant content of CO. Oxidant in line411 is passed from the oxidant source 410 into the combustor/turbineunit 490. Likewise, oxidant in line 412 is passed from the oxidantsource 410 to the syngas generation unit 420. As noted previously, theoxidant source 410 may be an ASU or other suitable unit configured forproviding oxygen in lines 411/412 and nitrogen in line 419, which isfurther discussed below. If needed, a further fuel source may be used tosupplement the fuel gas in line 445 and/or may be passed directly to thecombustor/turbine 490.

The power cycle components illustrated in FIG. 4 may be supplemented asdesired to include one or more elements already described above andillustrated in FIG. 1. The power cycle combustor/turbine 490 may be asingle, combined unit that is configured for both combustion andexpansion of the combustor exhaust, or a separate combustor and turbinemay be utilized. Expanded exhaust in line 491 exits thecombustor/turbine and is passed to the power cycle heat exchanger 495 tobe cooled and provide a cooled exhaust stream in line 496. The cooledexhaust is treated in the DeSNOx unit 470 to remove sulfur compoundsprimarily and optionally any nitrogen compounds present in the exhauststream. Sulfur and/or nitrogen compounds exit the unit 470 through line471 for disposal or other uses, and a substantially pure stream of CO₂(e.g., at least 80%, at least 90%, at least 95%, or at least 99% molarCO₂) exits in line 472. All or part of the CO₂ in line 472 may berecycled back to the power cycle combustor/turbine through line 476. Asillustrated, all or part of the CO₂ in line 472 may be passed in line476 a through the power cycle heat exchanger 495 for re-heating prior topassage in line 476 b to the combustor/turbine 490. The CO₂ in line 472may be compressed in compressor 472 a prior to passage back to thecombustor/turbine.

Hydrogen in line 443 and nitrogen in line 419 can be combined in theammonia synthesis unit 460 to provide a stream of ammonia in line 461 aspreviously discussed above. Part of all of the ammonia in line 461 maybe passed to the urea synthesis unit 480 to produce a stream of urea inline 481. The urea synthesis unit 480 can be fed with high pressurecarbon dioxide from the power production cycle and along with theammonia from the ammonia synthesis unit. The CO₂ for urea synthesis isprovided in line 474 and can be taken at the same or different pressureas the CO₂ that is recycled to the combustor/turbine unit 490 throughline 476. Steam may be input to the urea synthesis unit through line482. The steam may come from any suitable source, including an outsidesource. Moreover, in embodiments wherein steam may be formed in thepower cycle, steam can be withdrawn from the power cycle for use in theurea synthesis unit. As illustrated in FIG. 4, steam may be taken fromthe syngas generation unit in line 426, and all or part of the steam inline 426 may be input through line 482 into the urea synthesis unit 480.Likewise, all or part of the steam in line 426 may be input to theammonia synthesis unit 460 through line 462. As such, steam may beoutput from the ammonia synthesis unit 460 through line 463, and all orpart of the steam in line 463 may be passed through line 482 into theurea synthesis unit 480 through line 482.

As can be seen from the foregoing, the present disclosure can provide afacility that adapts a power production cycle (e.g., utilizing a fuelsource that is hydrogen-depleted) for the co-production of a hydrogenexport stream, which eliminates the typical gas processing equipmentrequired for such hydrogen production, leading to significant costsavings while simultaneously generating power and capturing carbondioxide normally emitted by this process. In some embodiments, suchfacility can be configured so that the part or all of the hydrogenexport stream may also be used in conjunction with part or all of acarbon dioxide export stream from a power production cycle to produceadditional value-added products, such as urea.

Examples Co-Production of Urea and Power

With reference again to FIG. 4, co-production of urea and power may beachieved, in some embodiments, utilizing more specific process andsystem conditions. In particular, a feedstock (line 421) is sent to agasifier or a SMR unit (420) to create raw syngas (line 425). Hydrogenis separated from raw syngas using a pressure swing absorption (PSA)separation unit (440) to provide hydrogen (line 443) for Ammoniasynthesis. CO-rich syngas (line 445) is sent to a power cycle combustorand turbine (490) for power generation. Turbine exhaust (containingpredominately carbon dioxide) is directed through line 491 into thepower cycle heat exchanger (495) for high grade heat recuperation. Acarbon dioxide stream (line 496) exiting the heat exchanger is thendirected to a water separator (DeSNOx unit 470) for water removal. Inthe water removal column, any SOx and NOx from the combustion flue gascan be removed in the forms of H₂SO₄ and HNO₃ (line 471). Sulfur speciesfrom coal used in the syngas production can be removed from the syngasvia conventional acid gas removal processes. Carbon dioxide exiting thewater separator unit in line 472 can be at ambient temperature and apressure of about 30 bar, and the carbon dioxide can be substantiallyfree of liquid water and SOx/NOx. A portion (e.g., about 60% to about95%, about 75% to about 95%, or about 80% to about 90% by weight) ofthis carbon dioxide stream can be sent back to the power productioncycle combustor/turbine through line 476 (preferably passing through theheat exchanger 495 for heat recovery via lines 476 a and 476 b). Theremaining portion of the carbon dioxide can be sent via line 474 to aurea synthesis unit. One or both of the CO2 streams in line 474 and 476may be first compressed to the same or different pressures in compressor472 a, which may be a multi-stage compressor with optional inter-stagecooling. Nitrogen in line 419 (e.g., from the power cycle ASU 410) andhydrogen in line 443 from the membrane separator 440 are sent to anammonia synthesis unit 460. The operating condition of the ammoniasynthesis unit 460 can be about 200-250 bar and about 400° C. to about500° C. Therefore, both of the nitrogen and the hydrogen are preferablyprovided in a compressed and pre-heated condition. The heat source ofthe ammonia synthesis process can be derived from the turbine exhaust inunit 490, an uncooled compressor (e.g., in the ASU 410 or the CO₂compressor 472 a, or another heat source in the system. Ammonia producedin line 461 from the ammonia synthesis unit 460 can be sold as achemical product or can be sent to a urea synthesis unit 480 along withsubstantially pure carbon dioxide from the power production cycle (line474).

Co-Production of Hydrogen and Power

A feedstock is sent to a gasifier or a SMR unit (e.g., unit 420) tocreate raw syngas (line 425). Hydrogen is separated from raw syngasusing a PSA separation unit (440) for synthesis of one or morechemicals, such as ammonia and urea (see the example above) or refineryoperations, such as hydrotreating. Hydrogen-depleted syngas (line 445)is sent to a power cycle combustor and turbine (490) for powergeneration. Turbine exhaust (containing predominately carbon dioxide) isdirected through line 491 into the power cycle heat exchanger (495) forhigh grade heat recuperation. A carbon dioxide stream exiting the heatexchanger is then directed through line 496 to a water separator forwater removal (which can be the DeSNOx unit 470 or a simple waterseparation unit (see element 130 in FIG. 1). Sulfur species from coalused in the syngas production can be removed from the syngas viaconventional acid gas removal processes, and such processes may be unitsincluded in syngas generation unit 420. Carbon dioxide exiting the waterseparator unit (line 472) can be at ambient temperature and a pressureof about 30 bar, and the carbon dioxide can be substantially free ofliquid water and SOx/NOx. All or a portion of this carbon dioxide streamcan be sent back to the power production cycle combustor/turbine asotherwise described above. The produced hydrogen can be used for thesynthesis of other chemicals, such as ammonia, or can be directly fedinto other processes, such as hydrotreating of hydrocarbons. Anyremaining portion of the carbon dioxide can be directed through optionalline 474 a to permanent underground sequestration or sent to ahydrocarbon synthesis unit 485 where H₂ from renewables and CO₂-freesources can be provided to generate additional hydrocarbon products. H₂in line 444 can be passed to the hydrocarbon synthesis unit 485 from oneor more outside sources. Such hydrogen source preferably comes from asource that is renewable and that has low or no associated carbondioxide emission. CO₂ for use in the hydrocarbon synthesis unit 485 maybe taken in line 474 a from the power cycle (or from anotherCO₂-containing stream in the power cycle) and/or may be taken from line251 exiting the CO₂ separation unit 250. CO₂ and H₂ are reacted in thesynthesis reactor 485 at a temperature of about 200° C. to about 400° C.or about 250° C. to about 350° C. (e.g., around 300° C.) and a pressureof about 20 bar to about 40 bar or about 25 bar to about 35 bar (e.g.,around 30 bar) in the presence of a composite catalyst. CO₂ from turbineexhaust can be cooled down to 300° C. and directly sent to the synthesisreactor through line 474 a, before or after compression. Since thesynthesis is an exothermic reaction, the heat released from the processcan be used to preheat the recycled CO₂ to increase the power cycleefficiency

Many modifications and other embodiments of the presently disclosedsubject matter will come to mind to one skilled in the art to which thissubject matter pertains having the benefit of the teachings presented inthe foregoing descriptions and the associated drawings. Therefore, it isto be understood that the present disclosure is not to be limited to thespecific embodiments described herein and that modifications and otherembodiments are intended to be included within the scope of the appendedclaims. Although specific terms are employed herein, they are used in ageneric and descriptive sense only and not for purposes of limitation.

1. A method for co-generation of power and one or more chemicalproducts, the method comprising: carrying out a power production cycleeffective for generating power; providing a heated stream comprising atleast carbon monoxide and hydrogen; cooling the heated stream comprisingat least carbon monoxide and hydrogen such that heat therefrom istransferred to at least one stream in the power production cycle and acooled stream comprising at least carbon monoxide and hydrogen isprovided; and subjecting the cooled stream comprising at least carbonmonoxide and hydrogen to one or more purification steps so as to providea stream comprising predominately hydrogen.
 2. The method of claim 1,wherein carrying out the power production cycle comprises carrying out acombustion step where fuel is combusted in the presence of a workingfluid comprising CO₂.
 3. The method of claim 1, wherein the heatedstream comprising at least carbon monoxide and hydrogen is a syngasstream.
 4. The method of claim 3, wherein the syngas stream is formed ina syngas generation unit.
 5. The method of claim 4, wherein heat createdin the power production cycle is transferred to the syngas generationunit.
 6. The method of claim 1, wherein heat from the heated streamcomprising at least carbon monoxide and hydrogen is transferred to astream of recycled CO₂ in the power production cycle.
 7. The method ofclaim 1, further comprising passing a portion of the cooled streamcomprising at least carbon monoxide and hydrogen to the power productioncycle for combustion therein.
 8. The method of claim 1, whereinsubjecting the cooled stream comprising at least carbon monoxide andhydrogen to one or more purification steps is effective to provide asecond stream that is a hydrogen-depleted stream.
 9. The method of claim8, further comprising passing at least a portion of thehydrogen-depleted stream to the power production cycle for combustiontherein.
 10. The method of claim 8, further comprising passing at leasta portion of the hydrogen-depleted stream through a separation unitconfigured to separate carbon dioxide therefrom.
 11. The method of claim10, wherein the separation unit is a low temperature CO₂ separation unitconfigured to cool the at least a portion of the hydrogen-depletedstream to a temperature sufficient for separation of the carbon dioxidein a liquefied form, and optionally wherein the low temperature CO₂separation unit is configured to cool the at least a portion of thehydrogen-depleted stream to a temperature that is about 2° C. to about25° C. greater than a freezing temperature of the at least a portion ofthe hydrogen-depleted stream.
 12. (canceled)
 13. The method of claim 1,further comprising combining at least a portion of the stream comprisingpredominately hydrogen with nitrogen from a nitrogen source underconditions effective to form ammonia.
 14. The method of claim 13,wherein the nitrogen source is an air separation unit, and optionallywherein oxygen from the air separation is utilized as an oxidant in oneor both of the power production cycle and a syngas generation unit. 15.(canceled)
 16. The method of claim 13, further comprising combiningcarbon dioxide with at least a portion of the ammonia under conditionseffective to form urea, and optionally wherein at least a portion of thecarbon dioxide is withdrawn from the power production cycle. 17.(canceled)
 18. A system for co-generation of power and one or morechemical products, the system comprising: a power cycle unit configuredfor power generation; a syngas generation unit effective for providing aheated syngas stream; one or more heat exchange elements configured forexchanging heat from the heated syngas stream to at least one stream inthe power cycle unit and providing a cooled syngas stream; and at leastone separation unit configured to separate the cooled syngas stream intoa first stream comprising predominately hydrogen and a second stream.19. The system of claim 18, further comprising an ammonia synthesis unitconfigured to receive at least a portion of the first stream comprisingpredominately hydrogen and to receive a stream comprising nitrogen andform a stream comprising ammonia.
 20. The system of claim 19, furthercomprising an air separation unit configured for providing oxygen to thepower cycle and for providing the stream comprising nitrogen to theammonia synthesis unit.
 21. The system of claim 19, further comprising aurea synthesis unit configured to receive at least a portion of thestream comprising ammonia and to receive a stream comprising carbondioxide and form a stream comprising urea.
 22. The system of claim 21,further comprising a CO₂ separation unit configured to receive at leasta portion of the second stream and provide the stream comprising carbondioxide.
 23. The system of claim 18, wherein the at least one separationunit includes one or both of a membrane separator and a pressure swingadsorption unit.